1. Field of the Invention
The invention relates to reduction of sulfur and nitrogen oxides and volatile trace metals from coal and solid fuel combustion in furnaces and boilers and a method of use.
2. Description of Related Art
Due to increasingly stringent and very costly emission regulations in recent decades, coal utilization has remained essentially constant in the U.S., despite its abundance and stable pricing. Historically, the primary concern has been emissions to the atmosphere of sulfur dioxide (SO2), nitrogen oxides (NOx), and ash particulates. In the past several years, the allowable emissions from these three pollutants have been further reduced. In addition, new requirements have been proposed, especially the emission of mercury, which is found in coal in minute quantities in the range of 20 to 100 parts per billion (ppb).
Many technologies have been developed and are available for commercial use to control each of these pollutants to the most stringent levels now being proposed by the U.S. Environmental Protection Agency (EPA). However, the common feature of these technologies is high, to extremely high, capital and/or operating costs. Historically, the favored approach has been to integrate the control processes for SO2, NOx, and particulates in the exhaust ducting of the boilers. This approach was also extended to adding controls for mercury and dioxin/furans to this same exhaust duct region. However, this has proven to be very costly because certain reactions are slow at these low temperatures, thereby necessitating large components. Also, it is known that some processes interfere with others, thereby necessitating further complexity in the process design. For example, mercury and dioxin/furan reduction improves as the temperature of the gases decreases below the acid dew point of SO2 and HCl. However, these acids corrode metal walls.
The overall result of applying current control methods to meet new regulations for coal fired power plants, which will require NOx reductions to 0.15 lb/MMBtu, 90% mercury removal, while maintaining existing SO2 reductions, has been estimated by EPA and the U.S. Department of Energy (DOE) to cost about $10 per megawatt-hour (MWH). This equals to 40% of the historical average, wholesale price of electricity of $25/MWH. To this cost must be added the probable future cost for reducing greenhouse gas emission, primarily carbon dioxide, CO2, which is produced in greater quantity from coal combustion than oil or natural gas.
In consequence of these high costs for pollution control, there has been in recent decades an almost total shift toward the use of natural gas for new electric power plants. However, natural gas is far less abundant than coal, and it also serves large existing markets, such as domestic and commercial heating. The problem with relying on natural gas as a power plant fuel was demonstrated in the economic recession of 2001 when the wholesale price of electricity decreased to its low historical level in the $25/MWH range, while the price of natural gas, with its multiple uses, remained relatively high. As a result, operators of natural gas fired-power plants were faced with declining revenues and high fuel prices. The economics of municipal waste incineration for waste disposal and energy recovery were also adversely affected by costly environmental regulations with the result that waste is now preferably disposed in landfills, with the result of future pollution from methane gas emissions from said sites.
As mentioned, known art has focused on treating the pollutants primarily in the exhaust ducting of boilers and furnaces. While the goal was to achieve an integrated approach, the reality has been that major pollutants have been treated with separate processes. While this approach will generally meet the most stringent current and proposed regulations, their implementation does not lead to any economic benefit from integration. For example, Selective Catalytic Reduction (SCR) will, in one step, reduce NOx to meet the most stringent regulations. However, it is extremely costly, and it offers no benefit to the control of SO2, or mercury. The result has been, as noted above, that EPA and DOE estimate meeting current and proposed emission regulations for NOx, SO2, and mercury will cost $10/MWH, which equals to 40% of the historical wholesale price of electricity of about $25/MWH.
Some of the volatile metals released during combustion, such as mercury and arsenic, can pass through fabric filters or ESP's (ElectroStatic Precipitators) into the atmosphere. The EPA has proposed using Best Available Control Technology (BACT) to remove the mercury emitted from U.S. coal burning plants. According to EPA's Reports to Congress (“Mercury Study Report to Congress, Vol. VIII (EPA-452/R-97-01010), December 1997 and “Air Pollutants from Electric Utilities-Report to Congress”, (453/R-98-004a), February 1998 (hereinafter referred to as “EPA”)), coal burning plants emit to the atmosphere about 33% of the mercury (Hg) emitted in the U.S. The DOE's current estimate is that removing 90%, or 37 tons of Hg, would cost about $5 billion, or $70,000/lb of Hg removed, or add $5/ton to the cost of U.S.'s coal production. Municipal solid waste (MSW) combustion systems account for 19%, or 27 tons of Hg emissions in the U.S. However, due to their higher concentration and different combustion process the cost of Hg removal is only, according to EPA, $11 to $47 million, or $211 to $870/lb of Hg.
It is critical to sharply reduce the cost of Hg removal from coal-fired power plants in the U.S. because the EPA reports (loc. cit.) state that Hg emission is a global atmospheric problem. Of the 5,000 to 5,500 tons emitted per year, 1000 tons are from natural sources, 2000 tons are re-emitted from prior years, and 2,000 tons are new emissions. Of this total, the U.S. emits only 3% (120 ton) and the U.S. coal fired power plants emit 1% (about 41 ton). By coincidence, 35 tons, which almost equals the total U.S. coal plant emissions, deposit in the U.S. from worldwide Hg emissions. Therefore, the U.S. would benefit directly by reducing global Hg emissions in Asia, whose power plants and other furnaces use the very high (up to 40%) ash coals.
The currently favored mercury emission process for coal fired power plants and MSW plants is injection of activated carbon with various spray injectors into the combustion gases flowing through the ducts upstream of the ash particle removal equipment (EPA, loc. cit.). One problem with this method is that injection must take place at gas temperature above the dew point for acid condensation from sulfur and nitrogen compounds and HCl in the gas, typically above 350° F. At these higher temperatures the mercury reduction effectiveness and also of dioxin/furans by activated carbon is greatly reduced. As the gas temperature is lowered the capture of Hg by activated carbon improves dramatically, with almost total removal measured at gas temperatures of about 220° F. It is, therefore, necessary to remove all the acid producing species, primarily sulfur and nitrogen oxides and chlorine, prior to cool down of the combustion gases to the temperatures below the acid dew points. In fact, as will be discussed below, it appears that the primary benefit in the prior art of injecting lime in large and complex spray dryers systems to reduce dioxin/furan emissions and improve mercury removal is to eliminate the corrosion from acid condensation at the low temperatures at which dioxin/furan emission reduction is effective.
In addition, the presence of other trace species that are in much higher concentrations in the gas stream, including SO2 and volatile trace metals, can attach to the porous activated carbon particle surface and prevent the gettering of the Hg. This is a critical deficiency in the use of activated carbon injection because the infinitesimal mercury concentration competes with far more numerous other species that can attach to the carbon. Sharply reducing these other species in the activated carbon injection zone is thus required.
A consequence of the above noted deficiencies for high Hg reductions are the need for extremely high carbon to Hg ratios. This results in replacing one environmental air emission problem with a future water and solid emission problem because mercury contaminated carbon must either be recycled or properly landfilled. To address this issue, EPA is turning to “life cycle assessment” or “cradle to grave” emission control to assure that removal of a pollutant from air, for example, does not create a water or solid waste problem.
To quantify this problem, one solution to mercury removal is coal washing at the mine that can remove up to 60% of the Hg with advanced deep cleaning processes [EPA, loc. cit.]. However, the Hg is deposited in large slurry ponds near the coalmines, and it may leach out to the water supply in the future. Similarly, the Hg removed in stack equipment of coal-fired power plants with the currently favored activated carbon injection processes require anywhere from 100's to 34,000 more carbon than Hg, (according to EPA), or 100,000 times more carbon, according to the DOE (EPA loc. cit.). This would replace 37 tons of Hg removed from the stack gases with 1 to 3+ million tons of mercury containing, solid waste. EPA (loc. cit.) estimates that this could increase electricity costs by around $2/MWh, while DOE estimates around $5/MWh, which equals 8% to 20% of the current wholesale electricity price of $25/MWh. EPA's (EPA, loc. cit) review of the many processes that remove mercury from stack gases all rely on some form of capture by specially prepared carbon, ranging in cost from activated carbon costing about $1,000/ton to proprietary compounds that cost 20 times as much.
Even if these mercury control technologies are adopted in the U.S., other volatile trace metals, such as lead or arsenic, or even minute traces of radioactive trace elements in coal ash, must also be removed from atmospheric emission. Furthermore, the deposition of these materials on U.S. soil from coal combustion overseas must be addressed because mercury from overseas deposits on U.S. soil and in the Pacific Ocean fisheries, whose fresh fish are eaten in Pacific Coast States. There is a greater than anticipated health risk from mercury as just reported in a study of 116 persons (Jane M. Hightower, “Study of Mercury in People's Blood”, Journal of Environmental Health Perspectives, Nov. 1, 2002) that ate more that 2 servings per week of fish, 89% had mercury levels above the 5 ppm recommended by the National Academy of Sciences.
Trace Metal Removal in the Air-Cooled, Cyclone Coal Combustor
Vitrification converts the fly ash that contains leachable toxic metals, such as arsenic and lead, into a chemically inert glassy material that can be used beneficially, (B. Zauderer & E. Fleming, “Air Cooled Cyclone Coal Combustor to Convert Ash to Inert Slag”, DOE SBIR-DE-AC01-88ER80568, Phase 1 Final Report, Mar. 13, 1989; Phase 2 Final Report: Jul. 13, 1992) and (2. B. Zauderer & E. Fleming, “A Cyclone Coal Combustor to Convert Municipal Incinerator Ash to Inert Slag”, Final Report EPA-SBIR Contract 68D90117, Apr. 30, 1991.). A key element of fly ash vitrification process was to prevent the re-evolution of volatile trace metals in the fly ash into the combustion gases in the air-cooled combustor. These trace metals were in two forms: one was trace metals that had remained trapped and dispersed throughout the ash particles during the original coal particle combustion in the power plant, and the other consisted of volatile metals that had condensed onto surfaces and internal pores structure of the fly ash particles in the stack gas stream and on the ash captured on the surfaces of the baghouse or ESP.
A “kinetic vitrification” process is based on the concept that the simplest and lowest cost method of limiting volatile metal emission to the atmosphere is to prevent them from evolving from the ash particles during combustion. As ash particles melt during combustion the volatile metals diffuse to the ash surface and vaporize. Therefore, to retain most of the volatile metals inside the ash particle or droplet it is essential to limit its residence time in the hot combustion gas. This is accomplished by the centrifugal force from the swirling combustion air that forces ash droplets to the liquid slag covered combustor wall. Since the volatile metals can still diffuse back to the liquid slag surface on the wall and re-evolve into the combustion gases, the slag must be rapidly drained into a water-cooled quench tank. Theoretical analysis (Zauderer & Fleming, loc. cit.) of the diffusion process in ash droplets and the slag layer show that this is feasible in a cyclone combustor whose refractory liner is air-cooled with the liners' solid surface in contact with the slag at the slag melting temperature.
As described in Zauderer & Fleming (loc. cit.), the time dependent diffusion equation for the time of evolution of a volatile metal from a spherical liquid slag droplet in the known range of particle size distribution is solved to determine the radial concentration of a trace metal. It is assumed that the concentration of the species, such as Hg, is uniformly dispersed in the sphere. The total loss of metal, e.g. Hg, is computed for the time of flight between fly ash particle injection to impact of the ash particle or droplet on the liquid slag covered combustor wall. The next step in the analysis is to solve the same diffusion equation for the liquid slag layer on the combustor wall. The solution provides the trace metal evolution from the slag layer. Here the total time is the slag layer drainage time, which is computed from the integrated, time dependent solution for viscous Stokes flow on the combustor wall. Air-cooling allows variation of the liner surface temperature as the slag melting temperature varies with different coal ashes. Additional variability in slag layer residence time is obtained by injection of calcium oxide based particles with the coal, which changes the slag viscosity.
The testing of this kinetic vitrification process was implemented in DOE and EPA projects (Zauderer and Fleming, loc. cit.) in which fly ash from a coal power plant and from a municipal incinerator were vitrified in Coal Tech's 20 MMBtu/hr, air-cooled combustor (Zauderer, U.S. Pat. No. 4,624,191, Nov. 25, 1986). As shown schematically in FIG. 1, the injected air from a pressure blower provides a swirling flow whose centrifugal force drives particles and droplets into the liquid slag layer that lines the inner combustor wall. Firing coal that is pulverized to 80% (by weight) passing a 200 mesh, results in about 75% of the ash that remains solid or is liquefied in the combustion gas being driven into the slag layer in the wall. The slag is drained through a slag tap at the downstream end of the combustor's floor, (FIG. 1). Ash particles as small as 10 microns impacted the slag layer within the 4-foot axial length of the combustor wall, with said particle or droplet transit time equal to or somewhat less than the combustion gas transit time of 80-millisecond in that combustor. Larger particles impact the wall sooner. For example, a 20-micron particle impacts the slag layer within 20 milliseconds, while a 50-micron particles impacts within 10 milliseconds.
Particles smaller than 10 microns will escape even from an air-cooled combustor twice as long, namely 8 feet, as was verified with such a combustor that has been in operation at Coal Tech Corp's facility in Philadelphia, Pa. since 1995. Therefore, retention of volatile trace metals in the fly ash tests cited above, whose mean particle size was somewhat under about 10 microns, was more difficult to achieve than with larger ash particles, except at very high swirl. Nevertheless, significant concentrations of volatile arsenic and lead were retained in the slag in the 20 MMBtu/hr-combustor (See FIG. 2). This was accomplished by operating the inlet swirl air pressure at 40 inches water gage (w. g.) where 90% of the ash was retained in the slag layer in the 4-foot long, combustor wall.
The theoretical analysis requires knowledge of diffusion data for these elements in the slag. For this purpose experimental data on the diffusion of sulfur and oxygen atoms in liquid metal oxide slag was used. It was determined that almost all the volatile metals could be retained in liquid ash droplets as small as 20 microns during the 20 millisecond interval between injection and slag layer impact. Even 10 micron-particles, which equaled the mean size of the fly ash used in the tests, retained (according to the analysis) 44% of volatile atoms in the 80 milliseconds interval from coal particle injection to slag layer impact.
The second critical step in kinetic vitrification is to prevent the re-evolution of the volatile metals captured in the slag layer during the time a liquid ash droplet or ash particle impacts the slag layer to its removal through the slag tap into the water filled quench tank. A slag element's residence time in the 20 MMBtu/hour air-cooled combustor's slag layer ranges from a few minutes to almost 30 minutes, depending on the slag layer thickness, slag layer temperatures, viscosity and slag mass flow rates. Again, using the O2 or S diffusion coefficients in liquid metal oxides as representative of volatile metals, e.g., As or Pb, but this time in a planar slab layer with a slag layer thickness of 2 millimeters and a surface temperature of 2300° F., it was computed that almost all volatile metals would remain in the slag if the slag residence time on the combustor wall was about 3 minutes, or less.
The above discussion of controlling the emissions of volatile trace metals, including mercury, focused on preventing their evolution from the ash particles and liquid ash droplets during their time of flight from injection inside the coal particles to their release during combustion and impact and dispersal in the slag layer on the combustor wall.
Sulfur Capture With Limestone or Lime Injection into a Slagging Cyclone Combustor
Several groups conducting research on different designs of slagging combustors in the late 1970's to early 1980's discovered independently that the injection of limestone into a slagging coal combustor would reduce the SO2 emissions. One group conducted tests in a 1 MMBtu/hr air cooled combustor (C. S. Cook, et. al, “Evaluation of Closed Cycle MHD Power”, Final Report, U.S. DOE Contract Mo: DE-AC01-78ET10818, November 1981) and (B. Zauderer, “Sulfur Capture with Limestone Injection in Cyclone Combustion Flows”, National Science Foundation Final Report, Grant No: CPE-8260265, Apr. 15, 1983, Hereafter “Zauderer-NSF”) in which 25% to 30% SO2 reduction was measured at the stack with limestone injection at a high Ca/S mol ratio of 9 to 1. The combustion gas residence time was about 50 m.sec. Another group (J. Stamsel, et. al., “TRW's Slagging Combustor System Tests” in 6th International Coal Utilization Conference, Houston, Tex. November 1983) also reported 10 to 45% capture with Ca/S mol ratios of 1 to 6.
These results were puzzling because the gas temperatures in slagging combustors is about 3000° F., while the reaction of calcined limestone, CaO, with SO2 to form CaSO4, reverses above about 2200° F. Furthermore, above this temperature melting of the particle's surface blocks access of SO2 gas molecule to the internal pore structure of the calcined particles, where almost the entire CaO—SO2 reaction occurs. Also, the published data for this “pore structure” reaction of CaO with SO2 in the temperature below 2200° F. showed that the reaction times needed for SO2 capture by CaO were in the range of 1 second, while the typical gas transit times in slagging combustors was generally under 100 m.sec. (Zauderer NSF, loc. cit.).
Zauderer suggested one possible explanation (Zauderer, NSF and Zauderer, “Analytical Investigation of Sulfur Capture and Slag rejection in Cyclone Coal Combustors”, Final Report, U.S. DOE Contract No. DE-AC22-82PC50050, Jan. 17, 1983) for the rapid sulfur capture, namely, that it occurred primarily near the injection zone of the coal, limestone, and air into the combustor. Rapid volatilization of the coal particles releases the organic matter in the coal, including the sulfur, resulting in ignition and heatup under locally high excess air conditions. Consequently, the local gas temperature is lower than the final gas temperature of about 3000° F. However, the temperatures are high enough to rapidly heatup and calcine the limestone or lime, resulting in an internal porosity that is substantially greater than the values reported in the literature with slow calcinations. Furthermore, the heatup rates of the CaO particles lag that of the combustion gases, and it is the surface temperature of the CaO particles that control the reaction with SO2. Therefore, the combination of a cooler initial combustion zone, a slower CaO heatup rate compared to the gas, and the greater particle porosity, all result in substantially greater sulfur capture than would be predicted by slower reactions under equilibrium gas and particle temperatures, as would exist in large boilers.
Since the smaller CaSO4 particles remain entrained for greater axial distances in the combustor they enter the final gas temperature region where the sulfur capture reaction should begin to reverse. This effect is reduced by the swirl of the gases that drives the particles into the slag layer where they melt and trap the sulfur. However, this latter effect is counterbalanced by the low solubility of sulfur in slag. It is, therefore, essential to remove the slag within several minutes.
The analysis of the time intervals for these gas phase and liquid slag phenomena were discussed above in connection with the vitrification of the volatile trace metals in coal ash. In fact, the capture of volatile trace metals by injected particles into the combustor would be governed by the same phenomena. The particles in the 10 to 100 microns size range remain entrained in the combustion gas from several milliseconds to 100 milliseconds, and that particles under 10 microns will be carried out of the combustor through the exit nozzle, and that the slag layer residence time in the combustor must be within a few minutes to prevent volatile gas re-evolution. This entire process for sulfur capture is described in Zauderer, (“Method of Optimizing Combustion and the Capture of Pollutants During Coal Combustion in a Cyclone Combustor”, U.S. Pat. No. 4,765,258.)
J. A. Woodroffe and J. S. Abichandani (“Sulfur Equilibrium Desulfurization of Sulfur Containing Products of Combustion”, U.S. Pat. No. 4,922,840, May 8, 1990) describe a sulfur capture process similar to Zauderer (U.S. Pat. No. 4,765,258), which they define as a “super equilibrium” process. Their application is to a toroidal, slagging combustor in which the coal, limestone, and air are all injected tangentially along the outer diameter of a “pancake” shaped combustor. The gases and slag are removed through an opening at the central bottom of the combustor. They teach the use of small particles of a mean size of 325 mesh and greater than 10 microns, and a 25 to 35 millisecond residence time in the combustion chamber. The two major deficiencies in their approach is that the toroidal combustor results in immediate injection into the nominal 3000° F. gases which greatly reduces the available time during which the CaO particles are in the colder temperature range where SO2 capture is favored. Furthermore, they fail to note the need for rapid slag removal to prevent sulfur re-evolution from the slag.
It has been difficult to achieve repetitive results and to optimize the sulfur capture process in the slagging combustor due to the competing reactions all of which occur within the combustor. For example, Zauderer reported (B. Zauderer, et. al., “Status of Coal Tech's Air Cooled Slagging Combustor”, in 2nd Annual Clean Coal Technology Conference, Atlanta, Ga., Sep. 8, 1993, Vol. 1, pp. 467-482) 70% SO2 reduction measured at the stack in tests in the 20 MMBtu/hour, air-cooled combustor with limestone injection at a Ca/S mol ratio of 4. However, a sampling probe at the combustor exit revealed that only 19% of this reduction occurred inside the combustor, with the balance occurring in the cooler, 2000° F. and lower, post-combustion zone downstream of the exit. This result suggested that despite transit through the 3000° F. gas temperature, the calcined CaO particles retained their pore structure, which is necessary for substantial SO2 capture, without “dead burning”, i.e. melting of the CaO particle surface. However, 80% SO2 reduction was measured during the same test series by injecting more reactive lime into the immediate post-combustion zone (nominal 2000° F. gas temperature) in the boiler, (See FIG. 1). The mean particle size of lime is about 10 microns, compared to about 74 microns for the limestone injected into the combustor. This lower temperature and smaller particle sizes account for the about 33% greater effectiveness of lime than limestone in sulfur capture in the combustor.
These tests were repeated (B. Zauderer, et. al, “Small, Modular, Low Cost Coal Fired Power Plants for the International Market”, in 7th Clean Coal Technology Conference, Tampa, Fla., January 1997) in a second-generation design of the 20 MMBtu/hour air-cooled combustor whose internal diameter was also 2.5 ft., but whose axial length was doubled to 8 feet, which resulted in a longer gas residence time. This resulted in major improvements in slag retention in the combustor in that all the slag was drained through the slag tap, as opposed to substantial slag flow out of the exit nozzle into the boiler. Slag flow out of the exit nozzle into the boiler has a much longer residence time at high temperature, which allows all the sulfur in the slag to re-evolve into the gas phase. In this longer combustor, with essentially no slag flow out of the combustor into the boiler, sulfur capture was higher, averaging 60% to 75% at Ca/S mol ratios of less than 3. Also, sulfur retention in the slag improved with values in the 10% to 20% range, which was measured in a high, 37% Indian ash coal. There the slag flow rates were in the 300 to 400 lb/hr range. However, this sulfur concentration in the slag did not represent a major fraction of the sulfur removed in the combustor by lime or limestone injection because the analysis of sulfur re-evolution from hot slag required slag mass flow rates above 500 lb/hr in order to limit the slag residence times in the combustor to 3 minutes.
In summary, a general observation from the prior art on sulfur capture in slagging combustors is that the published results do not teach how the process should be applied to large commercial scale (20 MMBtu/hour or greater) slagging combustors. The data shows a wide range of SO2 reduction with no clear correlation on how the process would scaleup or how to optimize it. High SO2 reductions have been reported; however, the relationship of these reductions to the removal of the reacted sorbent has been overlooked except in the prior work of Zauderer, who reported results of captured sulfur reporting to the slag. Also, Zauderer reported that in some cases, a significant part of the sulfur capture occurred in the immediate post-combustion zone with no evidence that transit of larger calcined limestone particles through the 3000° F. gas temperature in the combustor caused substantial “dead burning” of the particles, which would limit their sulfur capture effectiveness. Zauderer also attempted to isolate the capture and retention parts of the process by injecting gypsum as a sulfur gas generator in order to study the relationship of high slag mass flow rates on sulfur capture. Zauderer also used fly ash and more recently, high (70%) ash rice husk gasifier waste for this purpose. However, while a trend was established between increased slag flow and increased sulfur retention in slag, the total capture of 20% of the injected sulfur in the slag was still low.
Separately, in connection with using the air-cooled slagging combustor for mercury removal, EPA reported (EPA, loc. cit.) that the high ash residue in advanced coal-washing plants remove up to 60% of the mercury in the raw coal. It is almost certain that this mercury is in the inorganic ash, where retention of volatile trace metals within the ash particles released during coal particle combustion phase was found by Zauderer to be effective.
Injection of Activated Carbon for Mercury Reduction in the Combustion Gas Stream of the Boiler or Furnace Exhaust Ducting
As shown by analysis and tests (B. Zauderer & E. Fleming, DOE Contract: DE-AC01-88ER80568, loc. cit.) even at very high swirl in the air-cooled cyclone combustor, 10% of the ash mass, consisting of particles less than 10 microns, will exit the combustor. Also some fraction of the mercury in the organic part of coal will escape the combustor. It is therefore, necessary to add an additional process, such as the injection of various types of getters, either activated carbon or calcined lime, upstream of the particulate capture devices. Prior art (EPA, loc. cit) has shown that depending on factors, such as coal and ash type, reagent type, etc., most of the mercury can be removed from the gas stream. However, current injector schemes even with activated carbon that is enhanced with sulfur or iodine will in most cases require extremely high (up to 100,000 to 1) carbon to initial mercury mol ratios (EPA, loc. cit.).
Removal of SO2 and NOx from the Post Combustion Gas Stream
As noted above, Zauderer has developed and tested (B. Zauderer, “Method of Reducing NOx in Combustion Effluents” U.S. Pat. No. 6,048,510) a variable droplet size injection method that disperses droplets of a reagent of ammonia or urea dissolved in water throughout gas volumes ranging from the 20 MMBtu/hr boiler to 100 MWe power plant boilers. Since vaporization proceeds from the droplet surface inward, larger droplets penetrate deeper into the gas. Specialists in the field call this process Selective Non-Catalytic Reduction (SNCR). In 1997, coal-fired tests in the post-combustion zone of the 20 MMBtu/hour-boiler with these injectors resulted in NOx reductions from 1 lb/MMBtu by as much as 80% to 0.2 lb/MMBtu when the combustor operated under fuel lean conditions. Operating the combustor under fuel rich conditions reduced NOx from 1 lb/MMBtu to 0.4 lb/MMBtu. This was followed by the injection of SNCR in the post combustion zone that further reduced NOx to as low as 0.07 lb/MMBtu.
The identical injector design was also used by Zauderer (B. Zauderer, “A Method for Combined Reduction of Nitrogen Oxide and Sulfur Dioxide Concentrations in the Furnace Region of Boilers”, U.S. patent application Ser. No. 09/964,853, Sep. 29, 2001) to spray droplets containing a mixture of lime and urea into the 20 MMBtu/hr-combustor and immediately downstream of the combustor at gas temperature of about 2000° F. SO2 emissions were reduced by 80% while simultaneously reducing NOx. When added to the SO2 removed in the combustor with lime injection (B. Zauderer. U.S. Pat. No. 4,765,258) essentially all the SO2 is removed.
Another post combustion process for reducing NOx is called “reburn” in which additional fuel is introduced into fuel lean post-combustion gases in order to convert them to fuel rich conditions. This greatly reduces NOx as reported by Zauderer (B. Zauderer, “Reduction of Nitrogen Oxides by Staged Combustion in Combustors, Furnaces, and Boilers”, U.S. Pat. No. 6,453,830 B1). The latter invention disclosed the use of oil, biomass, and coal-water slurry as the “reburn” fuel. In tests conducted with the first two fuels, 50% NOx reductions were measured in tests in the 20 MMBtu/hour air-cooled cyclone combustor. The “reburn” NOx reduction is additive to staged combustion inside the combustor and to the SNCR reduction in the post-combustion zone.
Removal of Chlorinated Hydrocarbons-Primarily Dioxins and Furans from the Combustion and Post-Combustion Gas Streams
The chlorine in coal and in municipal solid waste results in the formation of dioxins and furan. However, the chlorine in coal is generally between 10 to 100 times lower in concentration than in municipal waste incinerators because the latter contains plastics that have substantially higher chlorine concentrations. The dioxins/furans are formed in the combustion zone at gas temperatures in the 2000° F. to 3000° F. range and separately in a narrow range in the post-combustion zone during regular gas cool down in the exhaust ducting below about 600° F. to 700° F. Zauderer performed a series of tests in the 20 MMBtu/hour combustor-boiler in which coal was co-fired with various amounts (up to 50% of the total mass flow rate) of a shredded municipal refuse derived fuel (RDF) (B. Zauderer, et. al, “Tests on Co-Firing of Coal and Refuse Derived Fuel (RDF) in A Slagging Cyclone Combustor Attached to a Package Boiler”, Coal Tech Corp., Merion, Pa. Report, Apr. 8, 1991, unpublished). The dioxins/furans were measured both inside the boiler and in the stack exhaust, and subsequently analyzed by Rossi, et. al. using EPA Method 23 (L. Bonfanti, et. al., “PCDD/Formation and Destruction from Co-Firing and RDF in a Slagging Combustor”, ENEL-Nuclear Research Center, Pisa, Italy, July 1992, Also in a paper presented at an International Environmental Conference, Lisbon, Portugal, 1992). The chlorine in the RDF was 10 times (0.5%) greater than that in the coal (<0.1%). With 40% RDF-60% Coal (mass flow) the dioxin and furans were about 60 times greater at the stack (almost 1,500 ng/NM3) than with coal only.
They were also measured with a water-cooled, suction gas probe inserted from the rear of the boiler, parallel and within several inches from the side wall. Here, dioxin/furan readings were 4 times higher than in the stack. However, gas sampling of SO2 and NOx in coal fired combustion tests 6 years later by Zauderer (unpublished) with the same probe and in the same boiler clearly showed that sampling at that location was not representative of the much hotter core combustion gas stream in the boiler. This non-uniformity was also confirmed in 3-dimensional modeling of the gas conditions in this boiler (S. Brewster, in a Report on DOE Contract DE-AC22-91PC91162). Consequently, the dioxin/furan samples taken in the boiler cannot be correlated to a specific gas state.
A major problem with these coal-RDF co-firing tests was the non-uniformity of the RDF feeding, which resulted in sharp periodic (order of 1 second) fluctuations in the visible flame inside the slagging combustor. It was believed that the high dioxin/furan emissions measured were due to these non-uniformities, a point also noted by others. This threw into question the stack gas results from the coal-RDF co-firing tests. To address this issue of uniform feeding, a series of tests were performed several years later (B. Zauderer, “Control of Dioxin Emissions from Waste Fuel Combustion by Co-firing with Coal”, DOE-SBIR Phase 1 Project Final Report, Contract: No: DE-FG05-93ER81554, Mar. 24, 1994). To assure uniform feed, calcium chloride pellets were used as a chlorine source, instead of RDF, and it was co-fired with the same 0.1% chlorine coal as previously. The chlorine level was increased in several steps to as high as 2.6% of the total injected mass flow, equal to 5 times greater than the Cl in the RDF. Nevertheless, even with 2.6% chlorine injection, the dioxin level measured at the stack was only 30 ng/Nm3, the same as with the 0.1% chlorine, coal test. This strongly suggested that non-uniform combustion is a major factor in dioxin formation.
In another test in which the calcium chloride injection produced a 1.2% chlorine mass flow rate, lime (calcium hydrate) was co-injected. The total calcium from both chemicals resulted in a total Ca/Cl mol ratio of 6.9, while that due to Ca(OH)2 alone was 3.4. The addition of calcium hydrate lowered the dioxin level by 45% and the furan by 12% compared to the baseline test without the lime. It also reduced the SO2 emissions by 72%.
In a report on the correlation of stack gas temperature with dioxin/furan emissions for several large municipal waste incinerators in Denmark (V. Boscak & G. Kotynek, “Techniques for Dioxin Emission Controls” in Proceedings of Municipal Waste Combustion Conference, Tampa, Fla., Apr. 15, 1991, Sponsored by EPA & Air & Waste Management Association, pp. 383-397) the measured reduction of the sum of the dioxin and furan emissions were lowered by a factor of 1000 to a little over 1 ng/NM3 as the stack gas temperature was reduced from 230° C. to 120° C. However, the results reported by Boscak are not directly comparable to Zauderer's results because a spray dryer absorber, with a presumably relatively long, single pass, gas residence time, into which a lime slurry was injected with a special injector, was installed upstream of the fabric filter leading to the stack.
Boscak also reported that injection of activated carbon or activated hydrated lime had no effect on these emissions. The lack of effect by these two species suggests that the lime's main function was mostly limited to neutralizing the acids formed from sulfuric acid and hydrochloric acid as SO2 and HCL are cooled below the acid dew point, and that the quenching of the gas stream by the water spray was the primary factor in lowering the dioxin/furan concentrations. This is a reasonable conclusion because the dioxin/furan reduction increased as the temperature was lowered, which indicates increased spray water flow and more rapid gas cooling. If this assessment is correct, it means that the use of such large spray dryers is a costly method for neutralizing these acids whose presence would corrode the ductwork. In any case, the results clearly indicate that stack gas temperature was the primary driver to the dioxin/furan reduction.
A spray dryer operates at low temperatures where the reaction between SO2 and HCl with lime is very slow and as a result a long residence time is needed for the reaction to proceed, which requires a large vessel. Prior art by Zauderer was cited above for removing the sulfur at high temperature. This type of spray dryer has been installed in a number of large (as much as 2000 tons/day of MSW) European and American MSW incinerator facilities. Brown and Felsvang (B. Brown and K. S. Felsvang, “Control of Mercury and Dioxin Emissions from U.S. and European MSW Incinerators by Spray Dryer Absorption”, Municipal Waste Combustion Conference, Apr. 15, 1991, pp. 675-705) presented results on dioxin/furan and mercury reduction in five MSW and RDF incinerators that used one type of spray dryer. Clarke also presented a technical paper on the same results of dioxin/furan and mercury reduction obtained in a Swiss MSW incinerator that was also reported by Brown, (M. J. Clarke, “A Review of Activated Carbon Technologies for Reducing MSW Incinerator Emissions” in Municipal Waste Combustion Conference, Tampa, Fla. [loc. cit.] April 1991, pp. 975-994).
Both review papers isolate the effect on adding activated carbon injection upstream of the lime slurry-spray dryer for both pollutants. A general comment on the three technical papers is that the presentation format provides test results, but little if any correlation to incinerator operating conditions. For example, the composition of the MSW and its heating value, which can vary widely even within one day are not given. In fact, the very wide variation in input conditions to the spray dryer reported in the last two papers validates the assessment that the MSW composition and probably combustion operating conditions varied widely. The absence of this information, which was certainly collected during the test, provides no guidance on the possible impact of combustion conditions on the magnitude of the emissions.
For present purposes, as noted above, all three papers report that the low temperature was the key factor in reducing dioxin and furan emissions. However, in contrast to Boscak, the other two papers report that the addition of activated carbon immediately upstream of the spray dryer in a 400 ton/day Swiss MSW incinerator reduced dioxin/furans by 98.9% to 5 ng/NM3 at the ESP outlet from 455 ng/NM3 at the lime-slurry drier inlet at 120° C. (248° F.). In the prior test without the carbon injection, the reduction was 75% to 69 ng/NM3 at the ESP outlet from 277 ng/NM3 at the dryer inlet. Note that the carbon injection was 59 milligram/NM3, which yields a ratio by weight of carbon to the incremental (over the spray drier) dioxin/furan reduction of 922,000 to 1. The ratio based on the dioxin/furan concentration at the inlet to the spray dryer was 130,000 to 1. However, since a large fraction of the dioxin reduction was due to rapid cooling of the stack gases, the contribution of the carbon to the total reduction is not known, only the incremental reduction can be totally quantified. This incremental removal of 34 grams per year of dioxin/furans, results in about 31,000 kg/yr of dioxin/furan impregnated carbon, which is dispersed in the fly ash, and requires proper landfill disposal. Since the U.S.-EPA regulation for MSW incinerators is 30 ng/NM3, as opposed to an apparent limit of under 5 ng/NM3 in Europe, it would appear that improvements in combustion performance combined with stack gas cooling should be sufficient to lower the emissions from 69 ng/NM3 to the U.S. limit without the need for activated carbon injection and its solid waste disposal requirement.
A qualitative measure of the ratio of activated carbon to pollutant can be obtained from the mercury reduction tests that were also conducted in this Swiss incinerator. The mercury emissions also decreased with decreasing outlet duct gas temperature from 140° C. to 110° C. The injection of lime in the spray dryer also contributed to gettering mercury. At 140° C., the Hg reduction across the spray dryer is 28%, while at 110° C. it was 43%. Injecting 30 mg/NM3 at 110° C., doubled the Hg reduction to 87%. In this case the carbon caused an incremental reduction of Hg of 105 μg/NM3 from which a carbon to Hg weight ratio of only 285 is deduced.
It thus appears that cooling of the stack gases is a far less costly process, than activated carbon injection for dioxin/furan removal. Also, use of a large spray drier vessel is a costly method of accomplishing said cooling. Furthermore, Boscak's reported lack of improvement in dioxin/furan reduction by use of activated carbon injection, while achieving an even lower emission of 1.4 ng/NM3 with only the lime slurry spray drier, suggests that activated carbon may not be necessary for dioxin/furan control. However, Boscak emphasized the importance of uniform combustion in removing excess ash from furnace walls that contain dioxin/furans, and removing fly ash at gas temperatures above 300° C., which reduces the catalytic effect of copper in said fly ash on dioxin/furan formation.
The alternative of applying to coal fired power plants the prior art from MSW incinerators of large spray driers with lime injection for acid neutralization would be quite costly because MSW plants have generally much lower thermal inputs than coal fired power plants. For example, the Swiss MSW plant had a capacity of 400 tons of MSW per day, which translates at best to less than 250 MMBtu/hr. This would equal to a very small 25 MW coal fired power plant. This may be one reason why DOE estimates (EPA, loc. cit.) that mercury removal for coal fired power plants would cost $70,000 per lb of Hg removed, while EPA states that said removal is 5 to 10 times less costly for MSW incinerators (EPA, loc. cit.). The MSW cost estimate is in general agreement with the prior MSW plant estimates cited above in which a costly spray dryer was used. Due to the low chlorine level in coal, dioxin/furan emissions, which are caused by chlorine in the coal, are much lower, and as yet not subject to regulation in coal fired power plants.
In 1994, Zauderer proposed (Zauderer, “DOE-SBIR Phase 2 Proposal to DOE Contract: No: DE-FG05-93ER81554”, unpublished) follow-on tests to validate this stack gas temperature effect and its relation to uniform combustion by replacing the calcium chloride source of chlorine with polyvinyl chloride pellets that would better simulate municipal solid waste. While the tests were not implemented, in September 2001 a pair of tests were implemented by Zauderer on a 90 MMBtu/hour, mass burn, municipal incinerator in Pennsylvania, which partially validated both the key role of uniform combustion in the primary flame zone on dioxin/furan emission levels and the importance of reducing stack gas temperatures on the magnitude of said emissions.
The prior art has shown that the major pollutants emitted during coal and MSW combustion, namely SO2, NOx, particulates, mercury, dioxins and furans, can be individually sharply reduced to below the current and proposed EPA regulatory levels. However, prior art reduction processes have little synergism between the individual pollutants, and each is quite costly. For example, SO2 reduction with a wet scrubber has little in common with NOx reduction with Selective Catalytic Reduction (SCR), or with mercury reduction with activated carbon.
While some prior art approaches may generally meet the most stringent current and proposed regulations, their implementation does not lead to any economic benefit from integration. For example, Selective Catalytic Reduction (SCR) will, in one step, reduce NOx to meet the most stringent regulations. However, it is extremely costly, and it offers no benefit to the control of SO2, or mercury. The result has been, as noted above, that EPA and DOE estimate meeting current and proposed emission regulations for NOx, SO2, and mercury will cost $10/MWH, which equals to 40% of the historical wholesale price of electricity of about $25/MWH.
Finally, the review of the prior commercial technology strongly suggests that the use of activated carbon for the control of dioxin/furans and mercury consisted of adding components to equipment that was apparently originally installed for SO2 and HCl emission control. However, this equipment, such as the spray dryer are large components, which are obviously costly. It is interesting that the three references cited in connection with their use contain no information on cost. Cost is the final determinant in use of any technology.